Method of consolidating an incompetent oil bearing formation



United States Patent 3,316,964- METHOD OF CONSOLIDATING AN IN COMPE. TENT OIL BEARING FORMATION Robert L. Gel-gins, Havertown, and Leon Weber, Wilkins Township, Allegheny County, Pa., assignors to Gulf Research & Development Company, Pittsburgh, Pa., a corporation of Delaware No Drawing. Filed Dec. 13, 1963, Ser. No. 330,241

5 Claims. (Cl. l6629) This invention relates to a method for consolidating an oil-bearing incompetent sandstone formation by coking the crude oil in the formation to deposit a carbonaceous residue binding the sand grains of the formation into a permeable consolidated formation.

Although carbonate rock formations such as limestones and dolomites are generally massive and well consolidated, many sandstone formations are unconsolidated or so poorly consolidated that they readily disintegrate. Such sandstone formations are hereinafter referred to as incompetent formations. When a Well is drilled into an incompetent sandstone formation containing oil, sand eroded from the formation flows into the well bore with the formation fluids and causes numerous operating problems, often requiring frequent work overs or abandonment of the well.

Many methods have been suggested for avoiding the problems involved in producing oil from incompetent sandstone formations such as injecting into the formation a resinous material which subsequently sets therein and binds the formation particles together. However, it is not always possible to obtain a uniformly consolidated sand barrier around the well bore using such a resinous material because the injected resin flows more readily into the higher permeability streaks of the formation than it does into the lower permeability streaks. In addition, the barrier formed by the resins and the sand grains is not always permeable, and often causes plugging of the formation around the well bore.

Another method suggested for alleviating the problems involved in producing oil from incompetent sandstone formations is the setting of screens or slotted casing or tubing in the well bore adjacent the formation. Such devices are not entirely satisfactory because sand production from the formation into the annulus of the Well bore around the slotted casing or screen often results in plugging of that annulus and requires a work over operation to restore the well to production. Gravel packing of the annulus formed by the wall of the well bore around the casing of the Well has also been suggested, but that method is expensive, involves a considerable amount of rig time and does not always prevent plugging of the formation around the well bore.

It has also been suggested that the formation particles can be consolidated by coking the oil in situ by reacting the oil with an injected hot gas containing oxygen. However the coking of crude oil with an oxygen-containing gas is preferably a low-temperature oxidation process requiring careful control of the injection rates and the reaction temperatures. If the temperature in the reaction zone exceeds about 500 F., the strength of the deposited coke is impaired. Furthermore, injection of an oxygen-containing gas into a formation causes spontaneous ignition of the crude oil unless the temperature of the oxygen-containing gas is carefully controlled within narrow limits.

This invention resides in a method for consolidating an incompetent subterranean oil-bearing sandstone formation whereby oil in the formation is contacted with chlorine to cause the deposition of a cokelike residue on the particles of sand to bind the sand into a permeable consolidated mass of substantial physical strength.

It has been found that chlorine reacts vigorously and exothermically with crude oil to produce both elemental carbon and significant quantities of heat for the in situ coking of the oil. Generally, chlorine can react with hydrocarbons by substitution, or hydrogen elimination, rather than by addition, in accordance with the following reactions:

C H +Cl C H Cl +HCl C H -I-Ci2 C 1H 2+ In an underground rock formation the energy liberated by the reaction is contained Within the area of the reacting materials and the resulting higher temperature favors the occurrence of the second of the above reactions. The liberation of carbon by this reaction and the destruction of colloids contained in the crude oil result in the formation of a carbonaceous reaction product which serves as an agent for binding the sand grains in the formation into a strong, permeable, substantially monolithic structure.

The production of elemental carbon increases with an increase inreaction temperature and the chlorination of crude oil in situ can produce a strong, permeable coked barrier at reaction temperatures ranging from 300 to 1600 F. An even more effective coked barrier is formed by the process of this invention when the reaction temperature is maintained within the range of from 400 to 1200" F. An exceptionally uniform and strong permeable barrier is formed when the temperature of the chlorine reaction is sustained between 560 and 1000 F.

The reaction temperature is a function of the chlorine flux through the formation. Preheating of the injected gas also causes a significant rise in reaction temperature, but an easier and more effective means of controlling the temperature in the reaction zone is by controlling the chlorine flux. An effective coked sand barrier can be obtained with a chlorine flux equal to or greater than 1.5 s.c.f./hr.- ft. A desirable range of chlorine flux is from 15 to 50 s.-c.f./hr.-ft. to assure a reaction temperature of between 400 to 1200" F. A preferred range for the chlorine flux, assuring a uniformly strong and permeable coked barrier, is from 20 to 40 s.c.f./hr.-ft.

The exothermic reaction of chlorine with crude oil to produce a coked sand barrier in an incompetent formation around a Well bore is not significantly sensitive to pressure within the range of pressures of several thousands pounds per square inch normally encountered in subsurface oil-bearing rock formations. Therefore, the lower limit of pressure in the reactionzone suitable for the process of this invention is the minimum pressure required for injecting the chlorine treating gas into the formation against the formation pressure. The upper limit for suitable pressures in the reaction zone is determined by the necessity for keeping the injection pressure of the treating gas low enough to assure that no substantial displacement of the crude oil from the formation near the well bore occurs. Obviously, these pressure limitations must be determined for each particular instance in which the process is used, but the existence of such broad limitations on suitable operating pressures places no significant restriction on the applicability of the process of this invention.

The following tests demonstrate the value of this process as a method for consolidating a sandstone formation. In a preliminary test conducted in an uninsulated glass tube, a sand pack of -120 mesh Ottawa sand having a porosity of 38 percent was mixed with melones crude oil to an oil saturation equal to 52 percent of the pore volume. The crude oil had a gravity of 93 API. Chlorine gas, under a gauge pressure of sever-a1 millimeters of mercury, was injected at an average flux of 15.5 s.c.f./hr.-lft Immediately after the injection of the chlorine gas, the temperature rose uniformly along the tube to approximately 18 F. above the ambient room temperature, but the high rate of heat loss from the uninsulated tube prevented a greater increase in temperature. Simultaneously, hydrogen chloride fumes began to evolve from the outlet end of the tube. There was no oil production contemporaneous with the production of the gas, and the resulting mixture of sand and coke was bonded into a hard, permeable mass.

A second test was conducted in a stainless steel tube having an inside diameter of /8 inch and containing three thermocouples. The tube was loosely packed with a putty-like mixture of Ottawa sand and Fruitvale crude having a gravity of 15.8 API. The packed tube contained 52 grams of oil and 200 grams of sand. The tube was placed in a furnace at an average temperature of approximately 135 F. The three thermocouples were placed one at either end and one in the middle of the packed tube and indicated temperatures along the tube of 109, 172 and 124 F. at the inlet, middle and outlet of the tube, respectively. These temperature ditferentials were the result of high heat losses from the furnace.

Chlorine was injected into the sand pack at a pressure of approximately 90 p.s.i.g. and a flux of 50.7 s.c.f./hr.-ft. Within two minutes after the commencement of chlorine injection, the temperature at each of the three thermocouple stations rose more than 50 F. as the result of a rapidly moving forward heat wave and remained fairly constant for 10 to 12 minutes. A reverse heat wave, traveling from the outlet end to the inlet end of the tube, then developed and rapidly elevated the temperature at the outlet end of the tube to 430 F. and the temperature at the middle of the tube to 300 F. During the test hydrogen chloride fumes evolved from the outlet end of the tube, and inspection of the sand pack after termination of the test indicated that a hard and Well consolidated coke had been formed. To test the quality and bonding strength of the coke, the consolidated material was immersed in benzene and showed no signs of disintegrating.

The physical properties of the coke produced in eight consecutive tests are presented in Table I and indicate that the compressive strength of the coke so produced varies over -a range of from 1000 to 2120 p.s.i. and that the permeability varies in a range of 0.14 to 3.1 darcys. It is therefore apparent that the coke produced by the reaction of chlorine with hydrocarbon liquids is of sufficient strength and permeability to support oil production from an underground sandstone formation.

TABLE I.-PROPERTIES OF CHLORINE COKED SAND Because of the temperature-vapor pressure characteristics of chlorine, it is possible that the gaseous chlorine injected into an underground formation will liquefy under the effect of the injection pressure. Liquid chlorine :acts as a solvent which might displace crude oil from the area of the formation contacted by the chlorine, thereby leaving insuificient oil around the well bore to provide a uniformly strong coked barrier. Consequently atest was conducted in which liquid chlorine was :injected into a packed, uninsulated glass tube to permit visual observation of the process. The results of this test indicated that upon first contacting the oil, liquid chlorine exhibits a vigorous exothermic reaction which supplies sufiicient heat to vaporize the injected chlorine and prevents the chlorine from displacing the oil from the volume of the sand pack contacted by the chlorine. Furthermore, in an adiabatic system such as an underground rock formation, the temperature induced by the exothermic reaction of chlorine with the crude oil will ordinarily exceed the critical temperature of chlorine and maintain the chlorine in the gaseous state throughout the formation even though the formation temperature and pressure are such as to condense chlorine in the absence of the heat of the reaction.

It is possible to prevent condensation of the injected gaseous chlorine in the well bore before it enters the formation and reacts with the oil by mixing with the chlorine a sufficient quantity of a permanent gas. When chlorine is mixed with a permanent gas, the partial pressure of the chlorine is reduced by dilution to a level at which condensation of the chlorine does not occur. Suitable permanent gases for use as diluents are carbon dioxide, nitrogen, flue gas, recycle gas containing hydrogen chloride that is liberated in the chlorination process, and the rare gases such as argon and neon. Carbon dioxide and hue gas are particularly suitable diluents for this process. Carbon dioxide dissolves in the oil to increase the oil volume and thereby increase the oil saturation around the well bore. Flue gases offer the advantage of providing additional heat to the reaction zone. A preferred permanent gas for this process is nitrogen because it is readily available and does not react chemically wit-h the hydrocarbon fluids contained in the formation.

To test the effects of a diluent inert gas on the chlorine coking reaction, two coking tests were conducted in a tube packed with Berea sand and Fruitvale crude into which was injected a gas mixture consisting of chlorine and nitrogen as an inert diluent. These tests were made with the tube held in a vertical position wit-h gas injection into the top and fluid production from the bottom of the tube. When the gaseous mixture was injected into the tube, a steam bank first developed and rapidly traversed the tube; then the oil-chlorine reaction zone, producing higher temperatures in the tube, slowly traveled through the tube. Pertinent data for these tests are presented in Table II.

Run 1 Run 2 Porosity (Percent Bulk Volume) 41. 4 48. 1

Oil Saturation (Percent Pore Volume) 38.3 32. 7 Water Saturation (Percent Pore Volume) 22. 1 18. 1

Oil Recovery (Percent Initial Oil) 57. 8 "46. 9 Water Recovery (Percent Initial Water) 97. 4 84. 0

Avg. Velocity of Steam Bank (ft./day).. 21.0 24. 4 Chlorine Flux (s.c.f./hr.-ft. 41. 8 35 20 Chlorine in Flux (Percent) 80. 6 46. 7 26. 7 Nitrogen Flux (s.c.f./hr.-ft. 10.0 40 55 Total Flux (s.e.f./hr. it. 51. 8 75 Average Peak Temperature 600 750 500 Avg. Velocity 01' Reaction Zone (ft./day) 5. 2 6. 6 4.4

*Reaetion not carried to completion.

In the first test of the effect of a diluent gas on the chlorine coking process, a flux of nitrogen was injected through the tube prior to the injection of chlorine while the inlet end of the tube was heated to 500 F. to expedite the establishment of steady state thermal conditions within the tube. The initial heating greatly accelerated the reaction rate and produced temperatures within the tube as high as 1020 F. The chlorine flux and pressure were changed several times throughout the first test. The reaction rate was not significantly influenced by pressure variations over a pressure range of from O to 55 p.s.i.g. However, the reaction rate and temperature proved ex tremely sensitive to chlorine flux, and alteration of the chlorine flux resulted in almost instantaneous changes in the temperature profiles. The last portion of this run was made with a mixture of nitrogen and chlorine at a constant flux of 51.8 s.c.f./-hr.- t of which 80.6 percent was chlorine. Because of the frequent changes made in operating conditions, a stable peak temperature was never obtained; however the temperature did rise to more than 600 F. The coke produced during this test exhibited no ill effects from continued immersion in benzene.

In the second test of the effect of a diluent gas on the chlorine coking process, the tube was not preheated and the reaction was initiated spontaneously with a chlorine flux of 35 s.c.f./hr.-ft. Because of extreme heat losses during the early part of the test the temperatures in the tube did not rise above 150 F. To reduce the heat losses, the external heat controls were turned on causing the temperature in the tube to rise rapidly and a steam bank to develop. The temperature remained at 240 F. until the steam bank had passed through the tube, at which time the temperature rose gradually to 600 P. Then a nitrogen flux of 40 s.c.f./hr.-ft. was added to the chlorine for a total gas flux of 75 s.c.f./h-r.-ft. The temperature throughout most of the tube then peaked at 750 F. The last part of this test was conducted with a lower chlorine fiux comprising a mixture of chlorine at 20 s.c.f./ hr.-ft. and nitrogen at 55 s.c.f./hr.-ft. As a result, the peak temperature declined to 500 F. The coked sand from this second combustion test was firm and consolidated and did not distintegrate when immersed in benzene.

If a mixture of chlorine and a diluent gas is employed in the process of this invention, the gaseous mixture must contain chlorine in a concentration of at least percent by volume to assure the creation of a substantial coked barrier around the well bore. The preferred concentration of chlorine in mixture with other gases is within the range of from 25 to 100 percent by volume.

When the chlorine coking process of this invention is employed to consolidate a subterranean rock formation, it is desirable that the injection of the chlorine into the formation be controlled to assure the proper placement of the treating gas in the incompetent formation to be consolidated. To facilitate this control over the injection of the chlorine treating gas, the following procedure is employed. A string of steel casing is run in the well bore and secured in place by a cement sheath deposited in the annulus of the well bore around the casing. The cement sheath must be of sufiicient length in the well bore to support the string of steel casing and must extend at least throughout the interval of the well bore adjacent the unconsolidated formation to be treated. A notching tool, or similar device, is then lowered into the casing and a horizontal ring is cut through the casing and the cement sheath into the incompetent sandstone formation.

Next, the section of the well bore adjacent the notch is isolated from fluid communication with the rest of the well bore by setting a straddle packer or equivalent means in the well bore. Then chlorine, or a. chlorine containing gas, is injected down the casing and through the notch into the formation.

The preceding description discloses a process for consolidating an incompetent sandstone formation by the in situ reaction of chlorine with the crude oil contained in the formation. The chlorine coking process of this invention has an advantage over other coking processes in that the chlorination process produces a carbonaceous reaction product at low rates of gas flux even at temperatures exceeding 500 F. to bind the formation particles into a strong permeable mass that is insoluble in hydrocarbon fluids.

Therefore we claim:

1. A method of consolidating sands having a petroleum crude oil distributed therethrough to form a hard permeable unitary mass comprising passing chlorine through the sands at a flux in the range from 15 std. cu. ft./hr./ sq. ft. up to the flux at which substantial oil is displaced from the sand.

2. A method as set forth in claim 1 in which the chlorine flux is in the range of 15 to 50 std. cu. f-t./hr./sq. ft.

3. A method as set forth in claim 1 in which the ch10- rine is in a mixture of chlorine with inert gas, the concentration of the chlorine being at least 10 percent by volume.

4. A method as set forth in claim 1 in which the chlorine is in admixture with nitrogen, the concentration of chlorine in the mixture being at least 25 percent by volume.

5. A method of consolidating sands having a petroleum crude oil distributed therethrough to form a hard permeable unitary mass comprising passing a mixture of chlorine and an inert gas through the sands at a flux adapted to increase the temperature of the sands to 300 to 1600 F., the concentration of chlorine in the mixture being at least 10 percent by volume.

References Eited by the Examiner UNITED STATES PATENTS 3,003,555 10/1961 Freeman 166-11 X 3,147,805 9/1964 Goodwin 166-25 13,156,299 11/1964 Trantham l66--11 3,193,012 7/1965 Huitt 16635 CHARLES E. OCONNELL, Primary Examiner. N. C. BYERS, Assistant Examiner. 

5. A METHOD OF CONSOLIDATING SANDS HAVING A PETROLEUM CRUDE OIL DISTRIBUTED THERETHROUGH TO FORM A HARD PERMEABLE UNITARY MASS COMPRISING PASSING A MIXTURE OF CHLORINE AND AN INERT GAS THROUGH THE SANDS AT A FLUX ADAPTED TO INCREASE THE TEMPERATURE OF THE SANDS TO 300 TO 1600* F., THE CONCENTRATION OF CHLORINE IN THE MIXTURE BEING AT LEAST 10 PERCENT BY VOLUME. 